The loss of drilling fluids presents several technological and cost challenges to the energy exploration industry. These challenges generally include the seepage losses of drilling fluids to the formation, the recovery of drilling fluids at surface and/or the disposal of drilling detritus or cuttings that are contaminated with drilling fluid. In the context of this description, “drilling fluid” is both fluid prepared at surface used in an unaltered state for drilling as well as all fluids recovered from a well that may include various contaminants from the well including water and hydrocarbons (both liquid and gas).
As is known, and by way of background, during the excavation or drilling process, drilling fluid losses can reach levels approaching 300 cubic meters of lost drilling fluid over the course of a drilling program. With some drilling fluids having values in excess of $1600 per cubic meter, the loss of such volumes of fluids represents a substantial cost to drill operators.
Drilling fluids are generally characterized as either “water-based” or “oil-based” drilling fluids that may include many expensive and specialized chemicals as known to those skilled in the art. As a result, it is desirable that minimal quantities of drilling fluids are lost during a drilling program such that many technologies have been considered and/or employed to minimize drilling fluid losses both downhole and at surface.
Additionally, in some areas the delivery of oil or water for the formulation of drilling fluids can present several costly challenges for some operations; specifically desert, offshore and even some districts where communities will not allow allocation of water for this use.
As noted above, one particular problem is the separation of drilling fluid and any hydrocarbons from the formation that may be adhered to the drill cuttings (collectively “fluids”) at the surface. The effective separation of various fluids from drill cuttings has been achieved by various technologies including but not limited to; hydrocyclones, mud cleaners, linear motion shakers, scroll centrifuges, vertical basket centrifuges (VBC), vacuum devices, and vortex separators. As known to those skilled in the art, these devices typically rent out at costs ranging from $1000 to $2000 per day and, as a result, can also represent a significant cost to operators. Thus, the recovery of fluids necessary to recover these costs generally requires that the recovered fluid value is greater than the equipment rental cost in order for the recovery technology to be economically justified. On excavation projects where large amounts of high-cost drilling fluid are being lost (for example in excess of 3 cubic meters per day), then daily rental charges for specialized separation equipment can provide favorable economics. In addition, an operator will likely also factor in the environmental effects and/or costs of disposal of drilling fluid contaminated drill cuttings in designing their drilling fluids/drill cutting separation/recovery systems.
Further still, past techniques for separating drilling fluid from drill cuttings have also used liquid spraying systems to deliver “washing” liquids to drill cuttings as they are processed over shaker equipment. Such washing liquids and associated fluid supply systems are used to deliver various washing fluids as the cuttings are processed over a shaker and can include a wide variety of designs to deliver different washing fluids depending on the type of drilling fluid being processed. For example, washing liquids may be comprised of oil, water, or glycol depending on the drilling fluid and drill cuttings being processed over the shaker. Generally, these washing fluids are applied to reduce the viscosity and/or surface tension of the fluids adhered to the cuttings and allow for more fluids to be recovered. However, these techniques have generally been unable to be cost effective for many drilling fluids as the use of diluting fluids often produces unacceptable increases in drilling fluid volume and/or changes in chemical consistency and, hence, rheological properties of the drilling fluid.
Thus, while various separation systems are often effective and/or efficient in achieving a certain level of fluids/cuttings separations, each form of separation technology can generally only be efficiently operated within a certain range of conditions or parameters and at particular price points. For example, standard shakers utilizing screens are relatively efficient and consistent in removing a certain amount of drilling fluid from cuttings where, during the typical operation of a shaker, an operator will generally be able to effect drilling fluid/cuttings separation to a level of 12-40% by weight of fluids relative to the drill cuttings (i.e. 12-40% of the total mass of recovered cuttings is drilling fluid). The range of fluids/cuttings wt % is generally controlled by screen size wherein an operator can effect a higher degree of fluids/cuttings separation by using a larger screen opening (eg. 50-75 mesh) and a lower degree of fluids/cuttings separation with a smaller screen opening (eg. up to 325 mesh). The trade-off between using a large mesh screen vs. a small mesh screen is the effect of mesh screen size on the quantity of solids passing through the screen. That is, while an operator may be able to lower the fluids retained on cuttings coming off the shaker with a larger mesh screen (50-75 mesh), the problem with a larger mesh screen is that substantially greater quantities of solids will pass through the screen, that then significantly affect the rheology and density of the recovered fluids and/or require the use of an additional and potentially less efficient separation technology to remove those solids from the recovered drilling fluids. Conversely, using a small mesh screen, while potentially minimizing the need for further downstream separation techniques to remove solids from recovered drilling fluids, results in substantially larger volumes of drilling fluids not being recovered, as they are more likely to pass over the screens hence leading to increased drilling fluids losses and/or require subsequent processing.
Accordingly, in many operations an operator will condition fluid recovered from a shaker to additional processing with a centrifugal force type device in order to reduce the fluid density and remove as much of the fine solids as possible before re-cycling or reclaiming the drilling fluid. However, such conditioning requires more expensive equipment such as centrifuges, scrolling centrifuges, hydrocyclones, etc., which then contribute to the overall cost of recovery. These processing techniques are also directly affected by the quality of the fluid they are processing, so fluids pre-processed by shakers using a coarse screen will not be as optimized as those received from finer screens.
Furthermore, the performance of centrifuges and hydrocyclones and other equipment are directly affected by the viscosity and density of the feed fluid. As a result, drilling fluid recovery techniques that send heavy, solids-laden fluids to secondary processing equipment require more aggressive techniques such as increased g-forces and/or vacuum to effect separation which will typically cause degradation in the drill cuttings.
Further still, such secondary processing equipment typically cannot process drill cuttings and drilling fluids at the same throughput values of a shaker with the result being that additional separation equipment may be required or storage tanks may be required to temporarily hold accumulated drilling fluid.
Thus, the operator will try to balance the cost of drilling fluid losses with the quality of the fluid that is recovered together with other considerations. While operators will typically have little choice in the quality of the cuttings processing and fluid recovery techniques available, many operators will operate separation equipment such that the recovered drilling fluid density from the separation equipment will be about 200-300 kg/m3 heavier than the density of the circulating fluid in the system. This heavier fluid which would contain significant quantities of fine solids and that when left in the drilling fluid will either immediately or over time impair the performance of the drilling fluid or any other type of fluid.
As a result, there continues to be a need for systems that economically increase the volume of fluids recovered from a shaker without negatively impacting the rheological properties of the recovered drilling fluid. More specifically, there has been a need for separation systems that result in recovered fluid densities in the range of 5-100 kg/m3 relative to the original fluid density and that do not affect rheological properties such as plastic viscosity and gel strength.
In addition, there has been a need to develop low-cost retrofit technologies that can enhance fluid recovery and do so at a fractional cost level to mechanisms and technologies currently employed. Further, there has been a need for retro-fit technologies that can be utilized on a variety of shakers from different manufactures and that can be used to enhance the operation of existing shakers.
Further still, there has been a need to develop separation technologies that enhance the operation of secondary separation equipment.
The use of vacuum technology has been one solution to improving the separation of drilling fluids. However, vacuum technology in itself presents various problems including insufficient cuttings/fluids separation that, as noted above, requires additional and expensive downstream processing, and its inability to effectively remove fines from the recovered drilling fluid which contributes to an increase in the density of the recovered drilling fluid. Moreover, aggressive vacuum systems will also degrade cuttings such that the problem of creating fines is increased.
In addition, various vacuum technologies may also present dust and mist problems in the workplace as, with past vacuum techniques, there is a need to regularly clean clogged screens with high pressure washes. High pressure washing of screens creates airborne dust and mist hazards to operators. Thus, there continues to be a need for technologies that minimize the requirement for screen washing.
Further still, there has been a need for improved fluid separation systems on the underside of a vacuum screen that allows relatively large volumes of air to be drawn through a vacuum screen to be effectively and efficiently separated from the relatively low volume of drilling fluid being drawn through a vacuum screen. That is, there has been a need for improved fluid/air separation systems. There has also been a need for vacuum technologies that assist in the oxidation of fatty acids within a drilling fluid that may reduce the need for additional emulsifiers.
Operationally, there has also been a need for improved methods of operating a vacuum system that effectively minimizes the risk of screen clogging but that also enables the use of finer screens.
Further still, there has been a need for systems that allow for the efficient replacement of screens but that also provide improved gaskets and sealing between the vacuum system and the screens.
Further still, there has been a need for retrofit systems that can be adapted to standard shakers without substantial modification to the existing shaking and that allow for quick and easy installation at a job site. In addition, there has been a need for retrofit systems that also allow for ready disassembly of the system for transport and/or maintenance.
Further still there has been a need for systems that provide improvements in the overall solids control program of a drilling program that allows greater flexibility in the management of the solids control equipment such that less fluid is delivered to the secondary processing equipment and wherein more expensive drilling fluids can be more efficiently and effectively recovered.
As is known, the entry of gas from a formation into circulating drill fluid occurs regularly during drilling operations where pressurized gasses from the formation mix with the circulating drilling fluid and dissolve within the drilling fluid which depending on the quantity and pressures may fully saturate the drilling fluid. This is particularly true as a drill bit enters a pay-zone within the formation and there is an influx of formation gas into the well bore which will lead to a saturation of drilling fluid with the formation gas. As the drilling fluid rises to the surface and is depressurized, gas may be released from the drilling fluid.
At surface, one of the first indicators of a “kick” or uncontrolled entry of gas into the circulating system is the appearance of a foamed drilling fluid at the shaker as gas bubbles form within the viscous drilling fluid. A foamed drilling fluid will typically result in a loss of drilling fluid over the shaker as the gas bubbles may not collapse over the shaker and/or minimize the contact of drill cuttings with the shaker screen thereby reducing the normal effectiveness of the shaker in a given time. In other words, the g-forces of the shaker may delay or be insufficient to immediately overcome the surface tension of the gas bubbles.
This problem is often addressed by increasing the screen size (i.e. a coarser screen), however, this action as noted above will result in lower quality drilling fluid being recovered. Alternatively, this problem is often addressed by by-passing the shaker to other gas separation equipment that may lead to drilling fluid degradation.
As a result, there has also been a need for systems that improve the ability of shaker systems to improve gas/fluid separation at a shaker as well as being able to provide effective information to operators about the location of a drill-bit relative to a pay-zone.
A review of the prior art reveals that various technologies including vacuum technologies have been used in the past for separating drilling fluids from drill cuttings including vibratory shakers.
For example, U.S. Pat. No. 4,350,591 describes a drilling mud cleaning apparatus having an inclined travelling belt screen and degassing apparatus including a hood and blower. U.S. Patent Publication No. 2008/0078700 discloses a self-cleaning vibratory shaker having retro-fit spray nozzles for cleaning the screens. Canadian Patent Application No. 2,664,173 describes a shaker with a pressure differential system that applies a non-continuous pressure across the screen and other prior art including U.S. Pat. No. 6,092,390, U.S. Pat. No. 6,170,580, U.S. Patent Publication 2006/01 13220 and PCT Publication No. 2005/054623 describe various separation technologies.
Thus, while past technologies may be effective to a certain degree in enabling drilling fluid/cuttings separation, the prior art is silent in aspects of the design and operation of separation devices that enable fluid removal to substantially improved levels. Specifically, the prior art is silent with respect to achieving fluids retained on cuttings level below about 12% by weight and that does not have an adverse effect on the density of recovered drilling fluid.
Examples of past systems and methods used to detect gas presence in wells include those systems and methods disclosed in United States Patent Publication 2006/0254421, U.S. Pat. No. 6,389,878, U.S. Pat. No. 4,635,735, U.S. Pat. No. 4,492,862 and U.S. Pat. No. 4,298,572.